This invention relates generally to methods for recovering hydrocarbons from a subterranean formation. In a particular aspect, the method of the present invention utilizes separate, discrete horizontal injection and production wells which are laterally and vertically spaced from each other and which are used to produce hydrocarbons from the lower horizontal wells at a rate faster than a driving fluid is injected into the upper horizontal wells. It is contemplated that the method of the present invention can be used to deplete a formation containing heavy, viscous oil, for example, more economically than other previously proposed recovery techniques.
Hydrocarbons, such as petroleum, cannot always be economically recovered from a subterranean formation using only the natural energy within the formation or the energy provided by pumping or some other primary means of production. For example, heavy, viscous oil typically cannot be economically produced using only primary production techniques. Formations of such oil can be found at, for example, the Athabasca, Cold Lake and Tangleflags (Lloydminster) oil sands deposits in Canada. To more economically deplete such formations, a secondary production technique is needed.
One category of known secondary production techniques includes injecting a fluid (gas or liquid) into a formation through a vertical or horizontal injection well to drive hydrocarbons out through a vertical or horizontal production well. Steam is a particular fluid that has been used. Solvents and other fluids (e.g., water, carbon dioxide, nitrogen, propane and methane) have been used.
These fluids typically have been used in either a continuous injection and production process or a cyclic injection and production process. The injected fluid can provide a driving force to push hydrocarbons through the formation, and the injected fluid can enhance the mobility of the hydrocarbons (e.g., by reducing viscosity via heating) thereby facilitating the pushing of the more mobile hydrocarbons to a production location. Recent developments using horizontal wells have focused on utilizing gravity drainage to achieve better results. At some point in a process using separate injection and production wells, the injected fluid may migrate through the formation from the injection well to the production well.
Preferably, a secondary production technique used for injecting a selected fluid and for producing hydrocarbons maximizes production of the hydrocarbons with a minimum production of the injected fluid. See U.S. Pat. No. 4,368,781 to Anderson. Thus, early breakthrough of the injected fluid from an injection well to a production well and an excessive rate of production of the injected fluid have been disclosed as not being desirable. See Joshi, S. D. and Threlkeld, C. B., "Laboratory Studies of Thermally Aided Gravity Drainage Using Horizontal Wells," AOSTRA J. of Research, pages 11-19, vol. 2, no. 1 (1985). It has also been disclosed that optimum production from a horizontal production well is limited by the critical velocity of the fluid through the formation. This is to avoid "fingering" of the injected fluid through the formation. See U.S. Pat. No. 4,653,583 to Huang et al. There is a disclosure, however, that "fingering" is not critical in radial horizontal wells. See U.S. Pat. No. 4,257,650 to Allen.
The foregoing disclosures have been within contexts referring to various spatial arrangements of injection and production wells. The spatial arrangements of which we are aware can be classified as follows: vertical injection wells with vertical production wells, horizontal injection wells with horizontal production wells, and combinations of horizontal and vertical injection and production wells. Because the present invention described below relates to a method using separate, discrete horizontal injection and production wells, brief reference will be made herein only to the prior horizontal injection well with horizontal production well arrangements of which we are aware.
Parallel horizontal injection and production wells disposed in a horizontal planar array have been disclosed. See U.S. Pat. No. 4,700,779 to Huang et al., U.S. Pat. No. 4,385,662 to Mullins et al. and U.S. Pat. No. 4,510,997 to Fitch et al.
Parallel horizontal injection and production wells vertically aligned a few meters apart are disclosed in the aforementioned article by Joshi and Threlkeld. See also: Butler, R. M. and Stephens, D. J., "The gravity drainage of steam-heated heavy oil to parallel horizontal wells," J. of Canadian Petroleum Technology, pages 90-96 (April-June, 1981) Butler, R. M., "Rise of interfering steam chambers," J. of Canadian Petroleum Technology, pages 70-75, vol. 26, no. 3 (1986); Ferguson, F. R. S. and Butler, R. M., "Steam-assisted gravity drainage model incorporating energy recovery from a cooling steam chamber," J. of Canadian Petroleum Technology, pages 75-83, vol. 27, no. 5 (September-October, 1988); Butler, R. M. and Petela, G., "Theoretical Estimation of Breakthrough Time and Instantaneous Shape of Steam Front During Vertical Steamflooding," AOSTRA J. of Research, pages 359-381, vol. 5, no. 4 (fall 1989); and Griffin, P. J. and Trofimenkoff, P. N., "Laboratory Studies of the Steam-Assisted Gravity Drainage Process," presented at the fifth annual "Advances in Petroleum Recovery & Upgrading Technology" Conference, Jun. 14-15, 1984, Calgary, Alberta, Canada (session 1, paper 1). Vertically aligned horizontal wells are also disclosed in U.S. Pat. No. 4,577,691 to Huang et al., U.S. Pat. No. 4,633,948 to Closmann and U.S. Pat. No. 4,834,179 to Kokolis et al. This last cited patent discloses a spacing wherein a horizontal injection well is at or near the top of the swept reservoir and the one or more production wells, which may either be vertical or horizontal, are substantially below the horizontal injection well relatively near the bottom of the reservoir. This latter patent contemplates only gravity effects for a miscible fluid. This is an examples of a "falling curtain of solvent" method using gravity effects to move hydrocarbons below the "curtain."
Staggered horizontal injection and production wells, wherein the injection and production wells are both laterally and vertically spaced from each other, are disclosed in Joshi, S. D., "A Review of Thermal Oil Recovery Using Horizontal Wells," In Situ, 11(2&3), 211-259 (1987); Change, H. L., Farouq Ali, S. M. and George, A. E., "Performance of Horizontal-Vertical Well Combinations for Steamflooding Bottom Water Formations," preprint of paper no. CIM/SPE 90-86, Petroleum Society of CIM/Society of Petroleum Engineers; U.S. Pat. No. 4,598,770 to Shu et al.; and U.S. Pat. No. 4,522,260 to Wolcott, Jr.
At least some of these prior configurations of which we are aware provide limited sweep efficiency. That is, any one set of injection and production wells affects a relatively small volume of the formation. As a result, a relatively large number of wells need to be drilled to produce throughout an extensive formation. This is particularly applicable to the technique using closely spaced vertically aligned horizontal wells.
These prior configurations can also limit the forces available for producing hydrocarbons. For example, using the prior configuration of two horizontal wells vertically spaced from each other, one aligned below the other, steam is injected through the upper well and hydrocarbons are produced from the lower well; however, after a very short initial time period, the production occurs only in response to gravity draining the hydrocarbons which have been heated by the injected steam. The steam itself does not provide a significant driving force because there is at most only a small pressure differential between the two wells regardless of the flow rate of the injected steam. Conversely, in the prior configuration wherein the horizontal wells are horizontally aligned, only a fluid driving force is available because gravity drainage tends to move the hydrocarbons downward, rather than across to an adjacent well.
With regard to staggered horizontal injection and production wells, the aforementioned article by Joshi, although showing a lower injection well and an upper production well, states that having the injection well near the top of the reservoir results in a large heat loss to the overburden above the reservoir (see Joshi, In Situ, at 223). Note also that the Shu et al. (U.S. Pat. No. 4,598,770) discloses a vertical spacing where the injection well is closer to the lower production wells, which are located near the bottom of the reservoir, than to the top of the reservoir. The examples of the Shu et al. patent disclose a greater injection rate than production rate. The Wolcott, Jr. (U.S. Pat. No. 4,522,260) discloses that explosives are to be detonated to create a rubblized zone between the injection and production wells. This rubblizing adds cost to the overall production process and it produces an uncertainty in the process due to the uncertainty of what will result from the downhole explosion.
Although any of the aforementioned techniques will at least theoretically produce hydrocarbons, there is the need for an improved method which not only produces hydrocarbons, but also produces them at a relatively higher net revenue. That is, there is the need for a method of economically depleting a formation to maximize the difference between (1) the projected revenue from hydrocarbons, such as specifically oil, produced from the formation by the method, and (2) the projected cost of forming and operating wells in the formation through which to produce the hydrocarbons. Such a method preferably should be suited to producing hydrocarbons more economically from difficult deposits, such as the heavy oil sands of Athabasca, Cold Lake and Tangleflags (Lloydminster) in Canada.